A variety of industrial as well as non-industrial applications use fuel burning boilers which typically operate to convert chemical energy into thermal energy by burning one of various types of fuels, such as coal, gas, oil, waste material, etc. An exemplary use of fuel burning boilers is in thermal power generators, wherein fuel burning boilers generate steam from water traveling through a number of pipes and tubes within the boiler, and the generated steam is then used to operate one or more steam turbines to generate electricity. The output of a thermal power generator is a function of the amount of heat generated in a boiler, wherein the amount of heat is directly determined by the amount of fuel consumed (e.g., burned) per hour, for example.
In many cases, power generating systems include a boiler which has a furnace that burns or otherwise uses fuel to generate heat which, in turn, is transferred to water flowing through pipes or tubes within various sections of the boiler. A typical steam generating system includes a boiler having a superheater section (having one or more sub-sections) in which steam is produced and is then provided to and used within a first, typically high pressure, steam turbine. While the efficiency of a thermal-based power generator is heavily dependent upon the heat transfer efficiency of the particular furnace/boiler combination used to burn the fuel and transfer the heat to the water flowing within the superheater section and any additional section(s) of the boiler, this efficiency is also dependent on the control technique used to control the temperature of the steam in the superheater section and any additional section (s) of the boiler.
As will be understood, the steam turbines of a power plant are typically run at different operating levels at different times to produce different amounts of electricity based on energy or load demands. For most power plants using steam boilers, the desired steam temperature set points at final superheater outlets of the boilers are kept constant, and it is necessary to maintain steam temperature close to the set points (e.g., within a narrow range) at all load levels. In particular, in the operation of utility (e.g., power generation) boilers, control of steam temperature is critical as it is important that the temperature of the steam exiting a boiler and entering a steam turbine is at an optimally desired temperature. If the steam temperature is too high, the steam may cause damage to the blades of the steam turbine for various metallurgical reasons. On the other hand, if the steam temperature is too low, the steam may contain water particles, which in turn may cause damage to components of the steam turbine over prolonged operation of the steam turbine, as well as to decrease the efficiency of the operation of the turbine. Moreover, variations in steam temperature also cause metal material fatigue, which is a leading cause of tube leaks.
Typically, each section (i.e., the superheater section and any additional sections such as reheater sections) of the boiler contains cascaded heat exchanger sections wherein the steam exiting from one heat exchanger section enters the following heat exchanger section with the temperature of the steam increasing at each heat exchanger section until, ideally, the steam is output to the turbine at the desired steam temperature. For example, some heat exchanger sections include individual primary superheaters that are connected in parallel, and which may in turn be connected in series to a final superheater. In such parallel connected or cascaded arrangements, steam temperature is controlled primarily by controlling the temperature of the water at the output of the first stage of the boiler which is primarily achieved by changing the fuel/air mixture provided to the furnace or by changing the ratio of firing rate to input feedwater provided to the furnace/boiler combination. In once-through boiler systems, in which no drum is used, the firing rate to feedwater ratio input to the system may be used primarily to regulate the steam temperature at the input of the turbines.
While changing the fuel/air ratio and the firing rate to feedwater ratio provided to the furnace/boiler combination operates well to achieve desired control of the steam temperature over time, it is difficult to control short term fluctuations in steam temperature at the various sections of the boiler using only fuel/air mixture control and firing rate to feedwater ratio control. Instead, to perform short term (and secondary) control of steam temperature, in many cases saturated water is sprayed into the steam at a point before the final heat exchanger section located immediately upstream of the turbine. This secondary steam temperature control operation typically occurs at the output of each primary superheater and before the final superheater section of the boiler (or sometimes prior to the final superheater sections located in each flow path). In other cases, burner tilt positions or flue gas dampers may be adjusted to perform secondary control of steam temperature. To effect this operation, temperature sensors are provided along the steam flow path and between the heat exchanger sections to measure the steam temperature at critical points along the flow path, and the measured temperatures are used to regulate the amount of saturated water sprayed into the steam for steam temperature control purposes (or to adjust other control mechanisms such as burner tilt positions and flue gas dampers).
In many circumstances, it is necessary to rely heavily on the spray technique to control the steam temperature as precisely as needed to satisfy the turbine temperature constraints described above. In one example, once-through boiler systems, which provide a continuous flow of water (steam) through a set of pipes within the boiler and do not use a drum to, in effect, average out the temperature of the steam or water exiting the first boiler section, may experience greater fluctuations in steam temperature and thus typically require heavier use of the spray sections to control the steam temperature at the inputs to the turbines. In these systems, the firing rate to feedwater ratio control is typically used, along with superheater spray flow, to regulate the furnace/boiler system. In these and other boiler systems, a distributed control system (DCS) uses cascaded PID (proportional-integral-derivative) controllers to control both the fuel/air mixture provided to the furnace as well as the amount of spraying performed upstream of the turbines.
However, cascaded PID controllers typically respond in a reactionary manner to a difference or error between a set point and an actual value or level of a dependent process variable to be controlled, such as a temperature of steam to be delivered to the turbine. That is, the control response occurs after the dependent process variable has already drifted from its set point. For example, spray valves that are upstream of a turbine are controlled to readjust their spray flow only after the temperature of the steam delivered to the turbine has drifted from its desired target. Needless to say, this reactionary control response coupled with changing boiler operating conditions can result in large temperature swings that cause stress on the boiler system and shorten the lives of tubes, spray control valves, and other components of the system.
Still further, control techniques which rely on multiple or cascaded loops can suffer from cross path interference which can lead to poorly performing control. For example, in cases in which a single variable master controller and a balancing single variable controller are used to perform coordinated control of two flow paths, these controllers are generally tuned separately. As a result, interference between these two coupled loops can cause control performance degradation and may even introduce control instability if the tuning is not performed correctly. Likewise, these control systems do not typically operate well when one of the control valves, such as one of the spray valves in one of the steam paths, is put into a manual mode (meaning that the master controller has no ability to control the position of that spray valve). In these circumstances, the master controller still uses the pre-tuned parameters or internal model (in the case of model based control) to perform control function calculations, even if the process gain (as seen from the master control output) has been reduced by half, because the spray valves in one path of the steam flow are in manual mode and thus do not respond to master control signal changes. This control situation can cause severe control performance degradation.